1. Field of the Invention
This invention relates to methods and systems for use in pore pressure prediction in oil and gas exploration. In particular, the invention provides methods, apparatuses and systems for more effectively and efficiently predicting formation pore pressure.
2. Prior Art
An accurate knowledge of formation pore pressure is required for the safe and economic drilling of deepwater wells. Ideally, the weight of the mud in the well bore used to control formation pressures should only be slightly greater than the formation pressure. Too low a mud weight may allow formation fluids to enter the well bore which, in the worst case, could lead to loss of the well and damage at the surface and could endanger personnel at the surface of the well. Too high a mud weight will give too low a rate of penetration, increasing the cost of drilling the well, and could lead to fracturing of the formation and creating an underground blowout. Drilling is particularly hazardous in the presence of dipping permeable layers which can communicate from deeper formations into the well being drilled, resulting in pressures much higher than would be normally anticipated. In deep water offshore exploration, the deep water reduces the difference between the pore pressure and fracture-pressure and therefore requires the pore pressure to be predicted as accurately as possible. A pre-drill estimate of formation pore pressures can be created either by using offset wells directly, or by using such offset well to determine appropriate transform such as a seismic velocity to pore pressure transform, and then applying this transform to seismic velocities at the proposed well location. Examples of such transforms include the method of Eaton, which is described in “The Equation for Geopressure Prediction from Well Logs” SPE 5544 (Society of Petroleum Engineers of AIME, 1975), and that of Bowers, which is described in “Pore pressure estimation from velocity data. Accounting for pore-pressure mechanisms besides undercompaction,” SPE Drilling and Completion (June 1995) 89-95, both incorporated herein by reference. As is known to those of skill in the art, other transforms (existing or to be developed in the future) may be used. These predictions can be updated while drilling the well, using Measurements While Drilling (MWD), Logging While Drilling (LWD), or other data obtained while drilling. Unfortunately, however, these methods only use-measurements for locations along the well trajectory, and thus ignore the effects of any property variations, such as velocity or pore pressure variation away from the well. This is particularly dangerous in the presence of dipping permeable beds, since these can communicate high overpressure at deeper depths away from the well to shallower depths at the well location, with the result that the pressures in the sands at the well location can be different from the pressures in the shale formations. This is illustrated in FIG. 1. Because sands, for example, are permeable, the variation of pore pressure with depth in the sands is given by the normal hydrostatic gradient of the fluid within the sand. Other permeable formations include limestone and dolomite. Although this application may discuss the invention in terms of sands, the invention also pertains to other permeable formations. Because they have low permeability, pore pressure in shale formations may increase with depth at a rate faster than the normal hydrostatic gradient. The pore pressure in the permeable formations and shales is only in equilibrium at one depth, the centroid. The concept of the centroid has been published. Some of the references are: “Pore Pressure and Fracture Pressure Determinations in Deepwater,” Martin Traugott, Amoco E & P Technology, Houston, Tex., Deepwater Technology Supplement to World Oil, August 1997 and “Stress, pore pressure, and dynamically constrained hydrocarbon columns in the South Eugene Island 330.eld, northern Gulf of Mexico,” Thomas Finkbeiner, Mark Zoback, Peter Flemings, and Beth Stump; AAPG Bulletin, v. 85, no. 6 (June 2001), pp. 1007-1031. Sands up-dip of the centroid have a higher pore pressure than the adjacent shales, which may lead to a kick while drilling, as the mud weight may be too low to hold the pressures of the sand formation in check. Sands down-dip of the centroid may be underpressured with respect to adjacent wells, leading to fluid loss into the sand while drilling as the mud weight may be higher than needed. It is generally preferable to drill high in a potential production formation, so wells frequently are be drilled into sand formations updip of the centroid.
FIG. 1 depicts a representation of the concept of a centriod. A well 10 is depicted schematically on the left side of FIG. 1 and pore pressures as a function of depth are depicted graphically on the right side of FIG. 1. In this example, the well 10 is being drilled of shore, as evidenced by a sea 15. The well 10 encounters overlying and underlying shale formations 20, 22 which have very little permeability, and a sand formation 25, which is permeable. (For simplification, only two shale formations 20, 22 and one sand formation 25 are depicted, with shale 20 overlying the sand 25 and shale 22 beneath the sand 25.) A curve depicting the hydrostatic gradient of the fluid within the sand, called the “normal hydrostatic pressure curve” 30, is plotted on the right side of FIG. 1 as a function of depth. A curve illustrating the pore pressure of the shale formations as a function of depth, called the “shale pore pressure curve” 35 herein, is depicted. The shale pore pressure curve 35 is drawn in FIG. 1 based on an assumption that the pressure in the shale formations 20, 22 is only a function of depth below mud line. This is an oversimplification and used for simplicity only. The actual pore pressure in the shales 20, 22 as a function of depth could be different and can be ascertained, as is known in the art, by other methods, such as an analysis of offset wells, seismic velocities or other techniques. Because shale formations are not permeable, the pressure in any given shale formation may be inconstant, with one point in a shale formation experiencing a pressure significantly different from that of second point in the same formation, if the depths of the first point and the second point are also significantly different.
A curve illustrating normal pore pressure in sand formations as a function of depth, called “normal sand pore pressure curve” 40 herein, is also depicted in FIG. 1. The intersection of the shale pore pressure curve 35 and the normal sand pore pressure curve 40, i.e. where the pressures of both curves 35 and 40 are equal, is found at the centroid 48. In other words, at the centroid the pressure in the overlying shale formation 20 is equal to the pressure in the sand formation 25.
Since the sand formation 25 is permeable, the pore pressures within the sand formation 25 will be fairly constant throughout the sand formation 25, that is, the pressure in the sand formation will be close to the pressure at the centroid 48, differing only by the hydrostatic gradient of the fluid created by the difference in the true vertical depth (TVD) of the point of interest in the sand formation 25 and the true vertical depth of the centroid 48. The well 10 is shown in FIG. 1 intersecting the sand 25 at a point updip of the centroid 48. Because the pore pressure in a sand formation updip of the centroid 48 is greater than the pressure in the adjacent shale formations 20,22, as the well passes through the sand interval 50, the well 10 will encounter pressures greater than would otherwise be expected from the pressure of the overlying shale 20. The pressure encountered by the well 10 in the sand 25 would be the pressure at the centroid 48, less the hydrostatic head of the fluid in the sand formation 25 from the TVD of the centroid (that is the pressure at point 55 on the normal hydrostatic pressure curve) to the TVD at which the well encounters the sand 25 (that is, the pressure at point 60 on the normal hydrostatic pressure curve).
Conversely, if the well 10 intersected the sand 25 down-dip of the centroid 48, the pore pressure in the sand would be the pressure a the centroid plus the additional hydrostatic head for difference in the well depth and the centroid depth and would be a lower pressure than the pressure the well would encounter in the shale formation 20. So the pressure in the sand downdip of the centroid will be slightly greater than the pressure at the centroid (but less than the pressure of the adjacent shale formations, while the pressure in the sand updip of the centroid will be less than the pressure at the centroid but greater than the pressure of the adjacent shales.
To phrase it in a different way, the pressure in the sand 25 at any particular depth can be determined. First determine the pressure in the shale formation 20 overlaying the sand 25 at the centroid location using any of the techniques available. At the centroid the pressure in the sand formation 25 will be equal to the pressure in the overlying shale formation 20. Then calculate the TVD difference between the top of the sand at the centroid and the top of the sand at the well location. The pressure in the sand at the well location then is given by pressure in the sand formation 25 at the centroid minus TVD hydrostatic gradient expressed in pounds per square inch (psi) or similar units. (Note that if the sand formation is downdip of the centriod, the TVD hydrostatic gradient difference will be a negative number, which when subtracted form the pressure at the centroid will yield a higher number than the pressure of the sand at the centroid.).
The shale pore pressure curve 35 illustrates formation pressures expected to be encountered in normally pressured shales and can be determined by using offset wells directly, or by using such an offset well to determine an appropriate transform, such as a seismic velocity to pore pressure transform. The centroid model was first introduced by Dickinson (1953) and was further elaborated by England et al. (1987) and Traugott and Heppard (1994), incorporated herein by reference. Although the centroid concept is well understood, there are no known techniques to use the centroid concept to predict the formation pressures in the sands ahead of the bit while drilling.
Thus the currently available approaches to predicting pore pressure available today have some important disadvantages, specifically they may not be accurate, especially in the presence of dipping permeable beds.